Loading (50 kb)...'
(continued)
An operator shall act immediately to correct a condition which creates a clear and present danger to life, health, property, or natural resources and shall immediately notify the division of the condition and the action taken to correct it.
s 1741. Definitions.
Unless this context otherwise requires, the following definitions shall apply to these regulations:
(a) "District" means oil and gas district as provided for in Section 3105 of Division 3 of the Public Resources Code.
(b) "Division," in reference to the government of this state, means the Division of Oil, Gas, and Geothermal Resources in the Department of Conservation.
(c) "Drilling fluid" means the fluid used in the hole during drilling or other proposed operations.
(d) "Field" means the same general surface area which is underlaid or reasonably appears to be underlaid by one or more pools.
(e) "Field rules" means unique requirements or procedures which may be established by the supervisor for a producing field.
(f) "Gas" means any natural hydrocarbon gas coming from the earth.
(g) (Reserved)
(h) "Oil" includes petroleum, and "petroleum" includes oil.
(i) "Operations" means any one or all of the activities of an operator covered by Division 3 of the Public Resources Code.
(j) "Operator" means any person drilling, maintaining, operating, pumping, or in control of any well.
(k) "Pool" means an underground reservoir containing, or appearing at the time of determination to contain, a common accumulation of crude petroleum oil or natural gas or both. Each zone of a general structure which is separated from any other zone in the structure is a separate pool.
(l) "Rework" means any operation subsequent to drilling that involves deepening, redrilling, plugging, or permanently altering in any manner the casing of a well or its function.
(m) "String" means a continuous length of connected joints of casing, liner, drill pipe or tubing run into the well, including all attached drilling, cementing, testing, producing, safety, and gravel-pack equipment.
(n) "Supervisor" means the State Oil and Gas Supervisor.
(o) "Well" means any oil or gas well or well for the discovery of oil or gas, or any well on lands producing or reasonably presumed to contain oil or gas or any well drilled for the purpose of injecting fluids or gas for stimulating oil or gas recovery, repressuring or pressure maintenance of oil or gas reservoirs, or disposing of oil field waste fluids or any well drilled within or adjacent to an oil or gas pool for the purpose of obtaining water to be used in production stimulation or repressuring operations.
Note: Authority cited: Section 3106, Public Resources Code. Reference: Sections 3000-3014, Public Resources Code.
s 1742. Well Identification.
(a) The number or designation, which includes the lease name when used, by which a well shall be known is subject to the approval of the supervisor and shall not be changed without the written consent of the supervisor.
(b) Identification of wells. The well designation shall be affixed to the wellhead or guard rail of each completed well. Wells completed from two or more zones shall have the zones individually identified at the wellhead. The supervisor may approve existing well identification methods if they substantially comply with the intent of this section. Identifying signs shall be maintained in a legible condition.
(c) Platforms, islands, or other fixed structures shall be identified at two diagonal corners of the platform or structure by a sign with letters and figures not less than 12 inches in height with the following information: the platform or structure designation, the name of lease operator, and the lease designation. The supervisor may approve abbreviations.
(d) Non-fixed platforms or structures shall be identified by two (2) signs with letters and figures not less than 12 inches in height affixed to opposite sides of the derrick to be visible from off the vessel with the following information: the name of the operator and the lease designation.
s 1743. General Requirements.
(a) It is understood that this division's approval of operations is contingent upon the continual fulfillment of all marine and pollution control requirements established by the U. S. Coast Guard and the State of California.
(b) All operations are to be conducted in a proper and workmanlike manner in accordance with good oil field practice.
(c) All installations shall comply with applicable provisions of Safety Orders of the State Division of Industrial Safety, including the Petroleum Safety Orders, the General Industry Safety Orders and the Unfired Pressure Vessel Safety Orders.
(d) An approved oil spill contingency plan that includes provisions for rapid deployment of containment and recovery equipment shall be in effect, and a copy of the plan shall be on file with this division prior to commencing operations.
(e) An approved plan for blowout prevention and control, "kick control plan," including provisions for duties, training, supervision, and schedules for testing equipment and drills, shall be on file with the division prior to commencing operations.
(f) Tubing, casing, or annulus open to an oil or gas zone shall be sealed off or equipped with a device to shut it in at the surface.
(g) A copy of the operator's proposals on division forms and subsequent approval of proposed operations by the division shall be available at the wellsite throughout such operations.
(h) Operators shall give adequate prior notice to the division's office of the district in which a well is located, of the time for inspections, and tests required by the division.
(i) Operations shall not deviate from the approved basic program without prior approval of the division. Additional requirements may be made at that time.
(j) Oil spills or slicks shall be reported to the agencies as specified in the California Oil Spill Disaster Contingency Plan and in the National Oil Hazardous Substances Pollution Contingency Plan.
(k) Blowouts, fires, hazardous gas leaks, disasters, major accidents, or similar incidents on or emanating from an oil or gas drilling, producing, or treating facility shall be reported to the division immediately.
Note: Authority cited: Section 3106, Public Resources Code. Reference: Section 3203, Public Resources Code.
s 1744. Drilling Regulations.
All exploratory wells and initial development wells on offshore sites shall be drilled or reworked in accordance with these regulations, which shall continue in effect until field rules are established. After field rules have been established, development wells shall be drilled or reworked according to such rules.
(a) Where sufficient geologic and engineering information is available from previous drilling, operators may make application to the supervisor for the establishment of field rules for each oil or gas pool or zone. The supervisor shall review field rules at least once a year and notify operators in writing of any change.
(b) Drilling or reworking of wells shall not commence without approval of the division. Notices of intention and approvals shall be considered cancelled if the proposed operations are not commenced within one year of receipt of the notice. Each proposal to drill or rework a well shall include all information required on division forms and a detailed work program including, when applicable, casing, cementing, drilling fluid, and blowout prevention programs, proposed bottom hole location, anticipated location of the intersection of each proposed zone of completion with the bore hole, anticipated pressures, and anticipated depths (both measured and vertical) of geologic formations, oil zones, gas zones, and freshwater zones. The casing, cementing, drilling fluid, and blowout prevention programs shall comply with either the following requirements or established field rules.
s 1744.1. Casing Program.
All wells shall be cased and cemented in a manner that will fulfill the requirements of Sections 3106, 3219, 3220, and 3222 of Division 3 of the Public Resources Code. The proposal to drill, redrill, or deepen shall include a casing program designed to provide for firm anchorage and for full protection of all oil, gas, or fresh water zones. All casing strings shall be new pipe or equivalent, capable of withstanding all anticipated collapse and burst pressures to be encountered or used. For the purpose of these regulations, the several strings in order of normal installation are conductor, first surface, second surface, intermediate, protective, and production.
Casing strings shall be run and cemented prior to drilling below the specified setting depth, subject to minor variations necessary to allow the casing to be set in firm compacted or consolidated stratum. All depths refer to true vertical depth (TVD) below the ocean floor, unless otherwise specified. Determination of proper casing setting depths shall be based upon all geological and engineering factors, including but not limited to the presence or absence of hydrocarbons, formation pressures, fracture gradients, lost circulation intervals, and the degree of compaction or consolidation of formations.
s 1744.2. Description of Casing Strings.
Names of strings used by the division are not always the same as those used by the federal government for wells drilled on the Outer Continental Shelf. Where there is a difference, the division name is given first followed by the federal name shown in parentheses.
(a) Conductor casing (drive or structural). This casing may be set by drilling, driving, or jetting to a depth of approximately 100 feet to provide hole stability for initial drilling operations. This casing may be omitted, when approved by the Offshore Unit, if there is geological evidence that hydrocarbons will not be encountered while drilling the hole for the first surface casing and is not needed for hole stability.
(b) First surface casing (conductor). This casing shall be set at a minimum depth of 300 feet or a maximum depth of 500 feet provided that this casing string shall be set before drilling into shallow strata known to contain oil or gas or, if unknown, upon encountering such strata.
(c) Second surface casing (surface). This casing shall be set at a minimum depth of 1,000 feet or a maximum depth of 1,200 feet below the ocean floor, but may be set as deep as 1,500 feet, in the event the surface casing is set at a depth at least 450 feet.
(d) Intermediate casing. This casing shall be set if the proposed total depth of the well is more than 3,500 feet. When surface casing is set at deeper than 1,000 feet, the proposed total depth of the well may be extended two (2) feet for each foot of surface casing below 1,000 feet.
Proposed Total Depth of Well or
Proposed Depth of First Full String Setting Depth for Itermediate
of Protective Casing (TVD in Feet Casing (TVD in Feet Below
Below Ocean Floor) Ocean Floor)
___________________________________ _______________________________
Minimum Maximum
3,500- 4,500 1,500 4,500
4,500- 6,000 1,750 4,500
6,000- 9,000 2,250 4,500
9,000-11,000 2,750 4,500
11,000-13,000 3,250 4,500
13,000-Below 3,500 4,500
(e) Protective casing. This casing shall be set when required by well conditions, such as lost circulation or abnormal pressures. When this string does not extend to the surface, the lap shall be cemented and tested by a fluid entry test to determine whether a seal between the protective string and next larger string has been achieved. The test shall be witnessed and approved by a division inspector and recorded on the driller's log.
(f) Production casing. This casing shall be cemented as noted in Section 1744.3 below and a test of water shut-off made above the zones to be produced or injected into. The test shall be witnessed and approved by a division inspector before completing the well for production or injection. In injection wells, the supervisor may approve the demonstration of the shut-off by running of a survey within 30 days after injection commences. The survey must show that injection fluid is confined to the approved injection interval.
When the production string does not extend to the surface, the lap between the production string and next larger casing string shall be cemented and tested as in the case of protective casing. The surface casing shall never be used as production casing unless all lower oil or gas zones are properly plugged.
s 1744.3. Cementing Casing.
The conductor (if drilled or jetted) and surface casings shall be cemented with sufficient cement to fill the annular space back to the ocean floor. The intermediate casing shall be cemented with sufficient cement to fill the annular space back to the ocean floor or at least 200 feet into the next larger string of pipe. The protective and production casings shall be cemented so that all fresh water zones, oil or gas zones, and abnormal pressure intervals are covered or isolated, and, in addition, a calculated volume sufficient to fill the annular space to at least 500 feet above cementing points, above oil or gas zones, and above abnormal pressure intervals not previously cased. When the cement behind casing is not returned to the ocean floor or through a lap, the amount of solid cement fill behind casing shall be determined by surveys acceptable to the supervisor. If the annular space is not adequately cemented by the primary operation, the operator shall displace sufficient cement to fill the required annular space. Upon demonstrating shut-off above the zones to be produced or injected into as indicated under (f) above, the operator may continue with the approved operations.
s 1744.4. Pressure Testing.
Prior to drilling out the plug after cementing, all blank casing strings, except the conductor casing, shall be pressure tested as shown in the table below. Loss in pressure shall not exceed 10 percent during a 30 minute test; corrective measures must be taken until a satisfactory test is obtained.
Casing String Minimum Surface Test Pressure
First surface 1 psi/ft. of depth
Second surface 1,000 psi
Intermediate, protective 1,500 psi or 0.2 psi/ft.,
and production whichever is greater
After cementing any of the above strings, drilling shall not be commenced until a time lapse of: eight hours for the first surface casing string and 12 hours for all other casing strings, or sufficient time for the bottom 500 feet of annular cement fill to attain a compressive strength of at least 500 psi based on a pretest of the slurry at the temperature and pressure at the cementing depth, using testing procedures as set forth by the American Petroleum Institute in RP 10B, 1972, incorporated here by reference.
All casing pressure tests shall be witnessed and approved by a division inspector prior to drilling out of the casing or perforating opposite possible oil or gas zones. Inspection of data recorded by a device approved by the division may be substituted for witnessing.
s 1744.5. Blowout Prevention and Related Well-Control Equipment.
This equipment shall be installed, tested, used, and maintained in a manner necessary to prevent an uncontrolled flow of fluid from a well. Division personnel shall use the current edition of Division of Oil, Gas, and Geothermal Resources Manual No. M07, "Oil and Gas Well Blowout Prevention in California," as a guide in establishing the blowout prevention equipment requirements specified in the division's approval of proposed operations.
Note: Authority cited: Section 3106, Public Resources Code. Reference: Section 3219, Public Resources Code.
s 1744.6. Drilling Fluid Program -General.
The characteristics, use, and testing of drilling fluid and the method of conducting related drilling procedures shall be such as are necessary to prevent the uncontrolled flow of fluid from any well. Quantities of drilling fluid materials sufficient to insure well control shall be maintained readily accessible for immediate use at all times.
(a) Drilling fluid control. Before starting out of the hole with drill pipe, the drilling fluid shall be circulated with the drill pipe hung just off bottom until the drilling fluid is properly conditioned. Proper conditioning requires circulation of the drilling fluid to the extent that the total annulus volume is displaced and until gas is removed. When coming out of the hole with drill pipe or tubing, the annulus shall be filled with drilling fluid before the drilling fluid level drops below a calculated depth of 100 feet below the derrick floor. A mechanical device that indicates the amount of drilling fluid required to keep the hole full shall be watched. If there is any indication of "swabbing" or influx of formation fluids, the inside blowout preventer shall be installed on the drill pipe, the drill pipe shall be run to bottom, and the drilling fluid properly conditioned. The drilling fluid shall not be circulated and conditioned except on or near bottom, unless well conditions prevent running the pipe to bottom. The fluid in the hole shall be circulated or reverse circulated prior to pulling drill-stem test tools from the hole.
(b) Drilling fluid testing equipment. Drilling fluid testing equipment for measuring viscosity, water loss, weight, and thixotropic properties shall be maintained on the drillsite at all times. Tests of the drilling fluid consistent with good operating practice shall be performed at the beginning of each eight-hour tour while drilling, with additional tests as conditions warrant. Results of tests shall be recorded on the driller's log. The following or comparable equipment for monitoring the drilling fluid system must be installed with the indicators at the driller's station and used throughout the period of drilling after setting and cementing the first surface casing.
(1) A recording mud-pit level indicator to determine mud pit volume gains and losses. This indicator shall include a visual and audible warning device.
(2) A mud volume measuring device for accurately determining mud volumes required to maintain fluid level at the surface while pulling the drill pipe from the hole.
(3) A mud return or full hole indicator to show when returns have been obtained, or when they occur unintentionally, and also to determine that returns essentially equal the pump discharge rate.
(c) Inspection of the complete drilling fluid system shall be made by a division inspector. Approval of the system is required prior to drilling out the shoe of the first surface casing.
s 1745. Plugging and Abandonment.
Plugging and abandonment operations shall not commence until approval has been obtained from the supervisor. Proposals to plug or plug and abandon shall be submitted on a division form for plugging or plugging and abandonment and accompanied by a detailed work program. The proposed plugging and abandonment program shall be deemed to have been approved if the supervisor does not give the operator a written response to the notice of intention within ten (10) working days. Under circumstances specified in Section 1740.5, the operator may receive conditional approval to commence operations.
The operator shall comply with the following minimum requirements which have general application to all wells. The supervisor may approve or require specific plugging materials and methods of operation to fulfill or exceed the minimum requirements.
s 1745.1. Permanent Plugging and Abandonment.
(a) Plugging in uncased hole. In uncased portions of wells, cement plugs shall be placed to extend from total depth or at least 100 feet below each oil or gas zone, whichever is less, to at least 100 feet above the top of each zone, and a cement plug at least 200 feet long shall be placed across an intrazone freshwater-saltwater interface or opposite impervious strata between fresh- and saltwater zones so as to confine the fluids in the strata in which they are found and to prevent them from escaping into other strata.
(b) Isolation of open hole. Where there is open hole immediately below casing, a cement plug shall be placed in the deepest cemented casing string from total depth or at least 100 feet below the casing shoe, whichever is less to at least 100 feet above the casing shoe.
(c) Plugging perforated intervals. A cement plug shall be placed opposite all perforations extending to a minimum of 100 feet above the perforated intervals, liner top, cementing point, or zone, whichever is higher.
(d) Isolating zones behind cemented casing. Inside cemented casing, a cement plug at least 100 feet long shall be placed above each oil or gas zone and above the shoe of the intermediate or second surface casing; a cement plug at least 200 feet long shall also be placed across an intrazone freshwater-saltwater interface or opposite impervious strata between fresh- and saltwater zones.
s 1745.2. Junk in Hole or Collapsed Casing.
In the event that junk cannot be removed from the hole, and the hole below the junk is not properly plugged, cement plugs shall be placed as follows:
(a) Sufficient cement shall be squeezed through the junk to isolate the lower oil, gas, or fresh water zones and a minimum of 100 feet of cement shall be placed on top of the junk, but no higher than the sea bed.
(b) If the top of the junk is opposite uncemented casing, the casing annulus immediately above the junk shall be cemented with sufficient cement to insure isolation of the lower zones.
s 1745.3. Plugging of Casing Stubs.
If casing is cut and recovered, other than that pulled for placing the surface plug, a cement plug shall be placed from at least 100 feet below to at least 100 feet above the stub.
s 1745.4. Plugging of Annular Space.
No annular space that extends to the ocean floor shall be left open to drilled hole below. If this condition exists, a minimum of 200 feet of the annulus immediately above the shoe shall be plugged with cement.
s 1745.5. Surface Plug Requirement.
A cement plug at least 100 feet long shall be placed in the well with the top between 50 and 150 feet below the ocean floor. All inside casing strings with uncemented annuli shall be pulled from below the surface plug. The casing shall not be shot or cut in a manner that will damage outer casing strings and prevent reentry into the well.
s 1745.6. Testing of Plugs.
Division tests for the location and hardness of cement plugs shall be verified by placing the total weight of the pipe string on the plug, or where there is sufficient depth, an open-end pipe weight of at least 10,000 pounds.
s 1745.7. Mud.
Any interval of the hole not plugged with cement shall be filled with mud fluid of sufficient density to exert hydrostatic pressure exceeding the greatest formation pressure encountered while drilling such interval.
s 1745.8. Clearance of Location.
All casing and anchor piling shall be cut and removed from not more than 5 feet below the ocean floor, and the ocean floor cleared of any obstructions, unless prior approval to the contrary is obtained from the appropriate marine navigation and wildlife agencies and a copy of the approval filed with the division.
s 1745.9. Temporary Abandonments.
Any well that is to be temporarily abandoned shall be mudded and cemented as required for permanent plugging and abandonment, but requirements of Sections 1745.1(d), 1745.4, 1745.5, and 1745.8 of this article may be omitted. For ocean-floor and platform sites, a mechanical bridge plug (retrievable or permanent) shall be set in the well between 15 and 200 feet below the ocean floor. For land fill, pier, and island sites, the well shall be securely capped or closed at the surface, until operations are resumed.
s 1745.10. Witnessing of Operations.
Operations to be witnessed by a division inspector include tests for location and hardness of plugs placed across oil or gas zones open to the well, across fresh water zones, across casing shoes, cementing through junk, and placing of the surface plug. Geologic or mechanical conditions may require changes or additions to the schedule of inspections.
s 1746. Well Records.
The operator of any well shall keep, or cause to be kept, an accurate record of each well consisting of but not limited to the following:
(a) A log and history for each well showing chronologically the following applicable data:
(1) Character and depth of formations, water-bearing strata, oil and gas-bearing zones, and lost circulation zones encountered.
(2) Casing size, kind, top, bottom, perforations, and attached equipment used.
(3) Tubing size, and depth, type and location of packers, safety devices, and other tubing equipment used.
(4) Hole size.
(5) Cementing and plugging operations including time, depth, slurry volume and composition, fluid displacement, fill, pressures used, and down-hole equipment used.
(6) Drillstem and formation tests including time, depth, pressures, and recovery (volume and description).
(7) BOPE installation, inspections, pressure tests, and drills.
(8) Shut-off, pressure, and lap tests of casing.
(9) Depth and type of all electrical, physical or chemical logs, tests, or surveys run.
(10) Wellhead specifications and method of production.
(b) Core record showing the depth, character, and fluid content of all cores, including sidewall cores, so far as determined.
(c) Filing records.
(d) Records at wellsite.
s 1746.1. Filing Records.
Well records shall be filed in accordance with the provisions of Sections 3215 or 3216, Article 4, Public Resources Code.
Note: Authority cited: Sections 3000-3013 and 3016, Public Resources Code. Reference: Sections 3203-3220 and 3227-3237, Division 3, Chapter 1, Article 4, Public Resources Code.
s 1746.2. Records of Wellsite.
During the performance of proposed operations, a copy of a well's tour reports shall be maintained at the wellsite. All pertinent well records shall be made available to the division inspector upon request.
Note: Authority cited: Sections 3000-3013 and 3016, Public Resources Code. Reference: Sections 3203-3220 and 3227-3237, Division 3, Chapter 1, Article 4, Public Resources Code.
s 1747. Safety and Pollution Control.
Operators shall equip wells and associated facilities with necessary safety devices and establish procedures as follows:
(a) Subsurface safety device. All wells capable of flowing oil or gas to the ocean floor shall be equipped with a surface controlled subsurface tubing safety valve installed at a depth of 100 feet or more below the ocean floor. Such device shall be installed in all oil and gas wells, including artificial lift wells, unless proof is provided to the supervisor that such wells are incapable of any natural flow to the ocean floor. For shut-in wells capable of flowing oil or gas, a tubing plug may be installed, in lieu of a subsurface safety device, and such plug shall also be installed when required by the supervisor.
(b) Subsurface safety devices shall be adjusted, installed, and maintained to insure reliable operation. When a subsurface safety device is removed from a well for repair or replacement, a standby subsurface safety device or tubing plug shall be available at the well location, and shall be immediately installed within the limits of practicability, consideration being given to time, equipment, and personnel safety. All wells in which subsurface safety device or tubing plug is installed shall have the tubing-casing annulus sealed below the valve or plug setting depth.
(c) Each subsurface safety device and tubing plug installed in a well shall be tested at intervals not exceeding one month and a report filed with the division within five (5) days. Failures shall be reported to the division immediately. The tests shall be performed in the presence of a division inspector following installation or reinstallation and at 90-day intervals thereafter. The supervisor may adjust the testing sequence based on equipment performance.
(d) The control system for the surface-controlled subsurface safety devices shall be an integral part of the shut-in system for the production facility.
(e) The operator shall maintain records, available at the structure or facility to any representative of the division, showing the present status and history of each subsurface safety device or tubing plug, including dates and details of inspection, testing, repairing, adjustment, and reinstallation or replacement.
Note: Authority cited: Section 3106, Public Resources Code. Reference: Sections 3106 and 3219, Public Resources Code.
s 1747.1. Safety and Pollution Control Equipment Requirements.
The following requirements shall apply to all offshore production facilities. Sections 1747.3, 1747.4, and 1747.9 shall also apply to mobile drilling structures. Sections 1747.2 and 1747.10 shall also apply to ocean floor completions or wells with submerged wellheads.
(a) The following devices shall be installed and maintained in an operating condition on all pressurized vessels and water separation facilities when such vessels and separation facilities are in service. The operator shall maintain records on the structure or facility showing the present status and history of each such device including dates and details of inspection, testing, repairing, adjustment, and reinstallation or replacement.
(1) All separators shall be equipped with high-low pressure shut-in sensors, low level shut-in controls, and a relief valve. High liquid level control devices shall be installed when the vessel can discharge to a gas vent line.
(2) All pressure surge tanks shall be equipped with a high and low pressure shut-in sensor, a high level shut-in control, gas vent line, and relief valve.
(3) Atmospheric surge tanks shall be equipped with a high level shut-in sensor.
(4) All other hydrocarbon handling pressure vessels shall be equipped with high-low pressure shut-in sensors, high-low level shut-in controls, and relief valves, unless they are determined by the supervisor to be otherwise protected. All low pressure systems connected to high pressure systems shall be equipped with relief valves.
(5) Pilot-operated pressure relief valves shall be equipped to permit testing with an external pressure source. Spring-loaded pressure relief valves shall either be bench-tested or equipped to permit testing with an external pressure source. A relief valve shall be set no higher than the designed working pressure of the vessel. On all vessels with a rated or designed working pressure of more than 400 psi, the high pressure shut-in sensor shall be set no higher than 5 percent below the rated or designed working pressure and the low pressure shut-in sensor shall be set no low er than 10 percent below the lowest pressure in the operating pressure range. On lower pressure vessels the above percentages shall be used as guidelines for sensor settings considering pressure and operating conditions involved, except that sensor setting shall not be within 5 psi of the rated or designed working pressure or the lowest pressure in the operating pressure range.
(6) All pressure-operated sensors shall be equipped to permit testing with an external pressure source.
(7) All gas vent lines shall be equipped with a scrubber or similar separation equipment.
s 1747.2. Safety Devices.
The following devices shall be installed and maintained in an operating condition at all times when the affected well (or wells) is producing. The operator shall maintain records on the structure or facility showing the present status and history of each such device, including dates and details of inspection, testing, repairing, adjustment, and reinstallation or replacement.
(a) All wells shall have a fail shut-in capability. For pumping wells incapable of natural flow to the ocean floor, an approved power source shut-off system may be used. On all flowing or gas lift wells the wellhead assemblies shall be equipped with an automatic failclose valve.
(b) All flowlines from wellheads shall be equipped with high-low pressure sensors located close to the wellhead. The pressure sensors shall be set to shut-in the well in the event of abnormal pressures in the flowline.
(c) All headers shall be equipped with check valves on the individual flowlines. The flowline and valves from each well located upstream of, and including, the header valves shall withstand the shut-in pressure of that well, unless protected by a relief valve with connections to bypass the header. If there is an inlet valve to a separator, the valve, flowline, and all equipment upstream of the valve shall also withstand shut-in wellhead pressure, unless protected by a relief valve with connections to bypass the header.
(d) All pneumatic, hydraulic, and other shut-in control lines shall be equipped with fusible material at strategic points.
(e) Remote shut-in controls shall be located on the helicopter deck and all exit stairway landings leading to the helicopter deck and to all boat landings. These controls shall be quick-operating devices.
(f) All pressure sensors shall be operated and tested for proper pressure settings monthly. Results of all tests shall be recorded and maintained on the structure or facility.
(g) All automatic wellhead safety valves shall be tested for holding pressure monthly. Results of all tests shall be recorded and maintained on the structure or facility.
(h) Check valves shall be tested for holding pressure monthly for at least four months. At such time as the monthly results are satisfactory, a quarterly test shall be required. Results of all tests shall be recorded and maintained on the structure or facility.
(i) A standard procedure for testing of safety equipment shall be filed with the division and posted in a prominent place on the structure or facility.
s 1747.3. Containment.
Curbs, gutters, and drains shall be constructed and maintained in good condition in all deck areas in a manner necessary to collect all contaminants, unless drip pans or equivalent are placed under equipment and piped to a sump which will automatically maintain the oil at a level sufficient to prevent discharge of oil into the ocean waters. Alternate methods to obtain the same results may be approved by the supervisor. These systems shall not permit spilled oil to flow into the wellhead area of a platform or pier.
s 1747.4. Emergency Power.
An auxiliary electrical power supply shall be installed to provide emergency power sufficient to operate all electrical equipment required to maintain safety of operation in the event the primary electrical power supply fails. The auxiliary system shall be tested weekly and the results recorded.
s 1747.5. Fire Protection.
A fire fighting system shall be installed and maintained in an operating condition in accordance with volumes 6 and 7 of the National Fire Codes, 1973, as appropriate, incorporated here by reference. A diagram of the fire fighting system, showing the location of all equipment, shall be filed with the division and posted in a prominent place on the structure. The system shall be tested monthly by the operator and a report filed with the division. Failure of any part of the system shall be reported to the division immediately.
Note: Authority cited: Section 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
s 1747.6. Detection System.
An automatic gas detector and alarm system shall be installed and maintained in an operating condition in accordance with the following:
(a) Gas detection systems shall be installed in all enclosed areas containing gas handling facilities or equipment, and in other areas classified as hazardous and defined in API RP 500 B, 1973, and the National Electric Code, 1971, both incorporated here by reference.
(b) All gas detection systems shall be capable of continuous monitoring. The sensitivity shall be maintained at a level that will detect the presence of combustible gas within the areas in which the detection devices are located.
(c) The central control shall be capable of giving an alarm at not higher than 60 percent of the lower explosive limit.
(d) The central control shall automatically activate shut-in sequences and emergency equipment at a point not higher than 90 percent of the lower explosive limit.
s 1747.7. Installation Application.
An application for the installation and maintenance of any gas detection system shall be filed with the division for approval and it shall include the following:
(a) Type, location, and number of detection or sampling heads.
(b) Cycling, non-cycling, and frequency information.
(c) Type and kind of alarm and emergency equipment to be activated.
(d) Method used for detection of combustible gas.
(e) Method and frequency of calibration.
(f) A diagram of the gas detection system.
(g) Other pertinent information.
Note: Authority cited: Section 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
s 1747.8. Diagram.
A diagram of the gas detection system showing the location of all gas detection points shall be filed with the division and posted in a prominent place at the structure.
s 1747.9. Electrical Equipment Installation.
All electrical equipment and systems shall be installed in accordance with the California Building Standards Electrical Code, 1971, the National Electric Code, 1971, and API RP 500 B, 1973, incorporated here by reference. On mobile drilling structures, certificated by the U. S. Coast Guard, this equipment shall be installed, protected, and maintained in accordance with the applicable provisions of CG-259, Electrical Engineering Regulations, 1971, incorporated here by reference.
s 1747.10. Testing and Inspection.
The safety and pollution control systems shall be tested and inspected every month and a report filed with the division. Failures shall be reported to the division immediately. A division inspector shall witness the tests and inspect the systems at the time production is commenced and at 90-day intervals thereafter. The supervisor may adjust the testing and inspection sequence based on equipment performance.
(a) After review by the supervisor and with his or her written approval, existing production facilities that substantially comply with the intent of Sections 1747 through 1747.9 will be exempt from these regulations. However, any changes or additions to existing platforms will comply with these regulations.
(b) The division shall be notified of all major production facility shutdowns anticipated to be in excess of 24-hour duration, whether intentional or otherwise. When inspected by a division inspector, a complete shutdown may be substituted for the next scheduled test of some or all of the safety systems.
Note: Authority cited: Section 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
s 1748. Waste Disposal and Injection Projects.
Disposal and injection projects are subject to the provisions of Section 1748.1 through 1748.3.
s 1748.1. Waste Disposal.
All discharges into the ocean shall conform to the requirements of the appropriate Regional Water Quality Control Board.
s 1748.2. Injection Projects.
All subsurface injection projects require prior approval of this division. An operator requesting approval to inject fluid into any subsurface strata must provide certain technical data regarding the project. This information must be submitted sufficiently in advance to enable the division to evaluate fully the possible effects of the project upon any oil, gas, or fresh water reservoirs that may be present. The completeness and accuracy of the following data filed will have a bearing on this division's decision to approve or disapprove the project.
(a) One or more geologic cross sections through the injection well at a scale that will clearly show the following:
(1) The injection well, or wells.
(2) A sufficient number of producing wells to show the geologic structure and stratigraphic relationship.
(3) Casing detail of all wells shown.
(4) The zone or zones to be injected into, other geologic units present, and the base of any fresh water aquifer.
(5) Location of any existing oil-water and oil-gas interfaces in or above the injection zone.
(6) The intervals of all geologic formations present.
(7) Fault block designations.
(b) A representative electric log from the surface to a depth below the producing zones (if not already shown on the cross section), identifying all geologic units, formations, oil or gas zones, and fresh water aquifers.
(c) Structural contour maps of markers at or near the top of each proposed injection zone showing the following:
(1) The location of the proposed injection well or wells, together with directional plots, bottom-hole locations, well status symbols, and zones open to production for all wells bottomed within the affected area.
(2) Reservoir characteristics such as pinchouts, permeability barriers and faults.
(3) Mineral lease boundary lines and fault block designations.
(4) Lines of cross sections.
(5) Lines showing original oil-water and oil-gas contacts.
(d) Letter containing engineering and geologic details of the project, in duplicate, including:
(1) Primary purpose.
(2) Reservoir characteristics of the injection zone; i.e., porosity, permeability, thickness (net and gross), present temperature and pressure, and present oil, gas, and water saturation.
(3) Casing diagrams, including cement plugs and cement fill behind casing, of all idle, plugged and abandoned, or deeper-zone producing wells within the area affected by the project.
(4) Source and analysis of the injection water and analysis of the water in the injection zone.
(5) Treatment of the water to be injected.
(6) Method of injection, i.e., through casing, tubing, tubing with packer, between strings.
(7) Maximum daily rate of injection, by well or wells.
(8) Maximum surface injection pressure anticipated (pump pressure).
(9) Precautions taken, or to be taken, to insure that the injected fluid is confined to the injection zone and to the area controlled by the operator.
(10) Protective methods used, if any, on injection lines and well(s), i.e., cathodic, etc.
(e) Copies of letters of notification sent to neighboring operators.
(f) Other data as required for large, unusual, or hazardous projects, for unusual or complex structures, for sensitive locations, etc. Examples: Isopach map, IsoGOR map, water-oil ratio map, IsoBAR maps, equipment diagrams, and safety precautions.
Note: Authority cited: Section 3013, Public Resources Code. Reference: Section 3301, Public Resources Code.
s 1748.3. Injection Requirements.
(a) Appropriate forms furnished by the division for proposal to drill or rework shall be completed and submitted to the division for approval whenever a new well is to be drilled for use as an injection well, or whenever an existing well is to be converted to an injection well, even if no work is required.
(b) An injection report on a division form shall be filed with this division in duplicate on or before the tenth day of each month, for the preceding month.
(c) A chemical analysis of the fluid (or gas) to be injected shall be made and filed with this division at least every two years, whenever the source of injection fluid is changed, or as requested.
(d) An accurate, operating pressure gauge or chart shall be maintained at the wellhead at all times.
(e) Fluid injection profile surveys shall be required for all injection wells within one month after injection has commenced, at least once every year thereafter for all high-pressure or high-volume injection wells, after any significant anomalous rate or pressure change, or as requested by the division, to confirm that the injection fluid is confined to the proper zone.
(f) Sufficient data shall be maintained to show performance of the project and to establish that no damage is occurring because of excessive injection pressure. These data shall be available for periodic inspection by personnel from this division.
(g) Injection shall cease upon written notice from the division if any evidence of damage is observed by the division or in its opinion is occurring.
(h) Additional requirements or modification of the above requirements may be necessary to fit individual circumstances.
s 1749. Cooperative Agreements.
Note: Authority cited: Section 3106, Public Resources Code. Reference: Section 3301, Public Resources Code.
s 1750. Purpose.
It is the purpose of this subchapter to set forth the rules and regulations governing the environmental protection program of the Division of Oil, Gas, and Geothermal Resources as provided for in Section 3106 of Division 3 of the Public Resources Code.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Sections 3000 through 3237, Public Resources Code.
s 1751. Policy.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code.
s 1752. Scope of Regulations.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code.
s 1753. Revision of Regulations.
Note: Authority cited: Sections 3013 and 3106, Public Resources Code.
s 1760. Definitions.
The following definitions are applicable to this subchapter:
(a) "Catch basin" means a dry sump that is constructed to protect against unplanned overflow conditions.
(b) "Designated waterways" means any named perennial or ephemeral waterways or any perennial waterways shown as solid blue lines on United States Geological Survey topographic maps and any ephemeral waterways that the supervisor determines to have a direct impact on perennial waterways.
(c) "Evaporation sump" means a sump containing fresh or saline water which can properly be used to store such waters for evaporation.
(d) "Environmentally sensitive pipeline" means any of the following:
(1) A pipeline located within 300 feet of any public recreational area, or a building intended for human occupancy that is not necessary to the operation of the production operation, such as residences, schools, hospitals, and businesses.
(2) A pipeline located within 200 feet of any officially recognized wildlife preserve or environmentally sensitive habitat that is designated on a United States Geological Survey topographic map, designated waterways, or other surface waters such as lakes, reservoirs, rivers, canals, creeks, or other water bodies that contain water throughout the year.
(3) A pipeline located within the coastal zone as defined in Section 30103(b) of the Public Resources Code.
(4) Any pipeline for which the supervisor determines there may be a significant potential threat to life, health, property, or natural resources in the event of a leak, or that has a history of chronic leaks.
(e) "Field" means the general surface area that is underlain or reasonably appears to be underlain by an underground accumulation of crude oil or natural gas, or both. The surface area is delineated by the administrative boundaries shown on maps maintained by the Supervisor.
(f) "Gathering line" means a pipeline (independent of size) that transports liquid hydrocarbons between any of the following: multiple wells, a testing facility, a treating and production facility, a storage facility, or a custody transfer facility.
(g) "Operations sump" means a sump used in conjunction with a drilling or workover rig during the period of time a well is being drilled or reworked.
(h) "Pipeline" means a tube, usually cylindrical, with a cross sectional area greater than 0.8 square inches (1 inch nominal diameter), through which crude oil, liquid hydrocarbons, combustible gases, and/or produced water flows from one point to another within the administrative boundaries of an oil or gas field. Pipelines under the State Fire Marshal jurisdiction, as specified by the Elder Pipeline Safety Act of 1981 (commencing with s 51010 of the Government Code, and the regulations promulgated thereunder) are exempt from this definition.
(i) "Sump" means an open pit or excavation serving as a receptacle for collecting and/or storing fluids such as mud, hydrocarbons, or waste waters attendant to oil or gas field drilling or producing operations.
(j) "Urban area" means a cohesive area of at least twenty-five business establishments, residences, or combination thereof, the perimeter of which is 300 feet beyond the outer limits of the outermost structures.
(k) "Urban pipeline" means that portion of any pipeline within an urban area as defined in this section.
( l ) "Waste water" means produced water that after being separated from the produced oil may be of such quality that discharge requirements need to be set by a California Regional Water Quality Control Board.
Note: Authority cited: Sections 3013 and 3782, Public Resources Code. Reference: Sections 3106 and 3782, Public Resources Code.
s 1770. Oilfield Sumps.
(a) Location. Sumps for the collection of waste water or oil shall not be permitted in natural drainage channels. Contingency catch basins may be permitted, but they shall be evacuated and cleaned after any spill. Unlined evaporation sumps, if they contain harmful waters, shall not be located where they may be in communication with freshwater-bearing aquifers. (continued)